Electrically Conductive Methods For In Situ Pyrolysis of Organic-Rich Rock Formations

ABSTRACT

A method and system for heating a subsurface formation using electrical resistance heating includes providing a wellbore which has a production portion that penetrates an interval of organic-rich rock within the subsurface formation. The method includes forming a fracture in the organic-rich rock along a plane that is generally parallel with the production portion of the wellbore. A first electrically conductive proppant is placed into the fracture. Second and third electrically conductive proppants are placed within the wellbore and in electrical communication with the first electrically conductive proppant. The second and third proppants are spaced apart, and have a bulk resistivity that is less than the bulk resistivity of the first proppant. The method then includes passing an electric current through the fracture such that heat is generated by electrical resistivity within the first proppant sufficient to pyrolyze at least a portion of the organic-rich rock into hydrocarbon fluids.

CROSS-REFERENCE TO RELATED APPLICATION

This application claims the priority benefit of U.S. Provisional Patent Application 61/500,462 filed 23 Jun. 2011 entitled ELECTRICALLY CONDUCTIVE METHODS FOR IN SITU PYROLYSIS OF ORGANIC-RICH ROCK FORMATIONS, the entirety of which is incorporated by reference herein.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates to the field of hydrocarbon recovery from subsurface formations. More specifically, the present invention relates to the in situ recovery of hydrocarbon fluids from organic-rich rock formations including, for example, oil shale formations, coal formations and tar sands formations. The present invention also relates to methods for heating a subsurface formation using electrical energy.

2. General Discussion of Technology

This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.

Certain geological formations are known to contain an organic matter known as “kerogen.” Kerogen is a solid, carbonaceous material. When kerogen is imbedded in rock formations, the mixture is referred to as oil shale. This is true whether or not the mineral is, in fact, technically shale, that is, a rock formed from compacted clay.

Kerogen is subject to decomposing upon exposure to heat over a period of time. Upon heating, kerogen molecularly decomposes to produce oil, gas, and carbonaceous coke. Small amounts of water may also be generated. The oil, gas and water fluids become mobile within the rock matrix, while the carbonaceous coke remains essentially immobile.

Oil shale formations are found in various areas world-wide, including the United States. Such formations are notably found in Wyoming, Colorado, and Utah. Oil shale formations tend to reside at relatively shallow depths and are often characterized by limited permeability. Some consider oil shale formations to be hydrocarbon deposits which have not yet experienced the years of heat and pressure thought to be required to create conventional oil and gas reserves.

The decomposition rate of kerogen to produce mobile hydrocarbons is temperature dependent. Temperatures generally in excess of 270° C. (518° F.) over the course of many months may be required for substantial conversion. At higher temperatures substantial conversion may occur within shorter times. When kerogen is heated to the necessary temperature, chemical reactions break the larger molecules forming the solid kerogen into smaller molecules of oil and gas. The thermal conversion process is referred to as pyrolysis or retorting.

Attempts have been made for many years to extract oil from oil shale formations. Near-surface oil shales have been mined and retorted at the surface for over a century. In 1862, James Young began processing Scottish oil shales. The industry lasted for about 100 years. Commercial oil shale retorting through surface mining has been conducted in other countries as well. Such countries include Australia, Brazil, China, Estonia, France, Russia, South Africa, Spain, Jordan and Sweden. However, the practice has been mostly discontinued in recent years because it proved to be uneconomical or because of environmental constraints on spent shale disposal. (See T. F. Yen, and G. V. Chilingarian, “Oil Shale,” Amsterdam, Elsevier, p. 292.) Further, surface retorting requires mining of the oil shale, which limits that particular application to very shallow formations.

In the United States, the existence of oil shale deposits in northwestern Colorado has been known since the early 1900's. While research projects have been conducted in this area from time to time, no serious commercial development has been undertaken. Most research on oil shale production was carried out in the latter half of the 1900's. The majority of this research was on shale oil geology, geochemistry, and retorting in surface facilities.

In 1947, U.S. Pat. No. 2,732,195 issued to Fredrik Ljungstrom. That patent, entitled “Method of Treating Oil Shale and Recovery of Oil and Other Mineral Products Therefrom,” proposed the application of heat at high temperatures to the oil shale formation in situ. The purpose of such in situ heating was to distill hydrocarbons and produce them to the surface. The '195 Ljungstrom patent is incorporated herein in its entirety by reference.

Ljungstrom coined the phrase “heat supply channels” to describe bore holes drilled into the formation. The bore holes received an electrical heat conductor which transferred heat to the surrounding oil shale. Thus, the heat supply channels served as early heat injection wells. The electrical heating elements in the heat injection wells were placed within sand or cement or other heat-conductive material to permit the heat injection wells to transmit heat into the surrounding oil shale while substantially preventing the inflow of fluids. According to Ljungstrom, the subsurface “aggregate” was heated to between 500° C. and 1,000° C. in some applications.

Along with the heat injection wells, fluid producing wells were completed in near proximity to the heat injection wells. As kerogen was pyrolyzed upon heat conduction into the aggregate or rock matrix, the resulting oil and gas would be recovered through the adjacent production wells.

Ljungstrom applied his approach of thermal conduction from heated wellbores through the Swedish Shale Oil Company. A full-scale plant was developed that operated from 1944 into the 1950's. (See G. Salamonsson, “The Ljungstrom In Situ Method for Shale-Oil Recovery,” 2^(nd) Oil Shale and Cannel Coal Conference, v. 2, Glasgow, Scotland, Institute of Petroleum, London, p. 260-280 (1951).

Additional in situ methods have been proposed. These methods generally involve the injection of heat and/or solvent into a subsurface oil shale formation. Heat may be in the form of heated methane (see U.S. Pat. No. 3,241,611 to J. L. Dougan), flue gas, or superheated steam (see U.S. Pat. No. 3,400,762 to D. W. Peacock). Heat may also be in the form of electric resistive heating, dielectric heating, radio frequency (RF) heating (U.S. Pat. No. 4,140,180, assigned to the ITT Research Institute in Chicago, Ill.) or oxidant injection to support in situ combustion. In some instances, artificial permeability has been created in the matrix to aid the movement of pyrolyzed fluids upon heating. Permeability generation methods include mining, rubblization, hydraulic fracturing (see U.S. Pat. No. 3,468,376 to M. L. Slusser and U.S. Pat. No. 3,513,914 to J. V. Vogel), explosive fracturing (see U.S. Pat. No. 1,422,204 to W. W. Hoover, et al.), heat fracturing (see U.S. Pat. No. 3,284,281 to R. W. Thomas), and steam fracturing (see U.S. Pat. No. 2,952,450 to H. Purre).

It has also been disclosed to run alternating current or radio frequency electrical energy between stacked conductive fractures or electrodes in the same well in order to heat a subterranean formation. Examples of early patents discussing the use of electrical current for heating include:

-   U.S. Pat. No. 3,149,672 titled “Method and Apparatus for Electrical     Heating of Oil-Bearing Formations;” -   U.S. Pat. No. 3,620,300 titled “Method and Apparatus for     Electrically Heating a Subsurface Formation;” -   U.S. Pat. No. 4,401,162 titled “In Situ Oil Shale Process;” and -   U.S. Pat. No. 4,705,108 titled “Method for In Situ Heating of     Hydrocarbonaceous Formations.”

U.S. Pat. No. 3,642,066 titled “Electrical Method and Apparatus for the Recovery of Oil,” provides a description of resistive heating within a subterranean formation by running alternating current between different wells. Others have described methods to create an effective electrode in a wellbore. See U.S. Pat. No. 4,567,945 titled “Electrode Well Method and Apparatus;” and U.S. Pat. No. 5,620,049 titled “Method for Increasing the Production of Petroleum From a Subterranean Formation Penetrated by a Wellbore.”

In 1989, U.S. Pat. No. 4,886,118 issued to Shell Oil Company. That patent, entitled “Conductively Heating a Subterranean Oil Shale to Create Permeability and Subsequently Produce Oil,” declared that “[c]ontrary to the implications of . . . prior teachings and beliefs . . . the presently described conductive heating process is economically feasible for use even in a substantially impermeable subterranean oil shale.” (col. 6, ln. 50-54). Despite this declaration, it is noted that few, if any, commercial in situ shale oil operations have occurred other than Ljungstrom's. Shell's '118 patent proposed controlling the rate of heat conduction within the rock surrounding each heat injection well to provide a uniform heat front. The '118 Shell patent is incorporated herein in its entirety by reference.

Additional history behind oil shale retorting and shale oil recovery can be found in co-owned U.S. Pat. No. 7,331,385 entitled “Methods of Treating a Subterranean Formation to Convert Organic Matter into Producible Hydrocarbons,” and in U.S. Pat. No. 7,441,603 entitled “Hydrocarbon Recovery from Impermeable Oil Shales.” The Backgrounds and technical disclosures of these two patent publications are incorporated herein by reference.

A need exists for improved processes for the production of shale oil. In addition, a need exists for improved methods for heating organic-rich rock formations in connection with an in situ pyrolyzation process. Still further, a need exists for methods that facilitate an expeditious and effective subsurface heater well arrangement using an electrically conductive granular material placed within an organic-rich rock formation.

SUMMARY OF THE INVENTION

The methods described herein have various benefits in improving the recovery of hydrocarbon fluids from an organic-rich rock formation such as a formation containing solid hydrocarbons or heavy hydrocarbons. In various embodiments, such benefits may include increased production of hydrocarbon fluids from an organic-rich rock formation, and providing a source of electrical energy for the recovery operation, such as for a shale oil production operation.

A method for heating a subsurface formation using electrical resistance heating is first provided. The method employs a single parent wellbore to create a propped, electrically conductive hydraulic fracture in the subsurface formation.

In one embodiment, the method includes forming the wellbore. The wellbore may be a single wellbore completed either vertically or substantially horizontally. Alternatively, the wellbore may be a multi-lateral wellbore wherein more than one deviated production portion is formed from a single parent wellbore.

The method also includes fracturing the formation from the wellbore. One or more fractures are formed from the wellbore using a hydraulic fracturing fluid. In shallow zones, that is, zones that are less than about 1,000 feet (305 meters) fractures tend to propagate vertically. In this instance, the wellbore is preferably substantially vertical. In deeper zones, that is, zones that are more than about 1,000 feet (305 meters) fractures tend to propagate horizontally. In this instance, it is preferred that the wellbore be completed with at least one horizontal portion, and then fractured to create a fracture plane that runs along the wellbore.

The method further includes placing a first electrically conductive proppant through the wellbore and into the fracture. The first electrically conductive proppant has a first bulk resistivity. The fracture is substantially filled with the first electrically conductive proppant to provide electrical communication along the wellbore. Where the wellbore has one or more horizontal sections, then the proppant may extend substantially from the heel of the wellbore to its toe. The step of placing the first electrically conductive proppant into the fracture is preferably done by pumping the proppant into the fracture using a hydraulic fluid.

The method also comprises placing a second electrically conductive proppant at a first location within the wellbore. The second electrically conductive proppant has a second bulk resistivity that is lower than the first bulk resistivity. The second electrically conductive proppant forms a local region of relatively high electrical conductivity in comparison to the first electrically conductive proppant. In this way, inordinate heat is not generated proximate the wellbore as the current enters or leaves the fracture.

The method also includes placing a third electrically conductive proppant at a second location within the wellbore. The third electrically conductive proppant is spaced apart from the second electrically conductive proppant. The third electrically conductive proppant has a third bulk resistivity that also is lower than the first bulk resistivity. The third electrically conductive proppant forms another local region of relatively high electrical conductivity in comparison to the first electrically conductive proppant. The second and third proppants may be comprised of substantially the same material.

The first electrically conductive proppant is intermediate to and in electrical communication with the second and third electrically conductive proppants. The method further includes passing electric current through the fracture such that heat is generated by electrical resistivity within the first electrically conductive material. Where the formation comprises organic-rich rock, the heat is sufficient to pyrolyze at least a portion of the organic-rich rock into hydrocarbon fluids. Where the formation comprises bitumen, the heat is sufficient to mobilize heavy hydrocarbons to flow towards a producing well. In either instance, the heat generated within the first and second locations is less than the heat generated within the fracture. In this respect, the compositions of the first, second, and third proppants are such that heating of the subsurface formation takes place primarily from the first electrically conductive proppant longitudinally along the fracture.

In one embodiment, the step of passing electric current includes providing separate electrical connections to the first and second locations, respectively, with the electric connections being configured to transmit electricity from a surface electricity source.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the present inventions can be better understood, certain drawings, charts, graphs and flow charts are appended hereto. It is to be noted, however, that the drawings illustrate only selected embodiments of the inventions and are therefore not to be considered limiting of scope, for the inventions may admit to other equally effective embodiments and applications.

FIG. 1 is a three-dimensional isometric view of an illustrative hydrocarbon development area. The development area includes an organic-rich rock matrix that defines a subsurface formation.

FIGS. 2A through 2G provide side, cross-sectional views of a wellbore. The wellbore penetrates through a subsurface formation and into an interval of organic-rich rock. The wellbore is formed for the purpose of heating the organic-rich rock.

FIG. 2A provides a first cross-sectional view of the wellbore. Here, the wellbore has been lined with a string of casing. In addition, an electrically conductive lead has been run into the wellbore, terminating at an upper end of the organic-rich rock formation.

FIG. 2B provides another cross-sectional view of the wellbore. Here, the casing has been perforated along a substantial portion of the organic-rich rock formation. However, the casing along an upper portion of the organic-rich rock formation is left unperforated.

FIG. 2C shows a next view of the wellbore used for heating the organic-rich rock formation. Here, the organic-rich rock is undergoing fracturing. A first electrically conductive proppant has been injected into the wellbore and into the surrounding rock to form a fracture plane.

FIG. 2D presents a next step in the completion of the wellbore. Here, a string of coiled tubing has been run into the wellbore, and a packer has been set proximate a lower end of the organic-rich rock. A second electrically conductive proppant is injected through the coiled tubing and placed along a bottom of the wellbore and a bottom portion of the organic-rich rock formation.

FIG. 2E presents yet another step in the completion of the wellbore. Here, the string of coiled tubing has been removed, leaving the second electrically conductive proppant at the bottom of the wellbore. In addition, the casing has now been perforated along an upper portion of the organic-rich rock formation.

FIG. 2F presents still another step in the completion of the wellbore. Here, the string of coiled tubing has again been run into the wellbore. The packer has been set just below the new perforations at the upper end of the organic-rich rock formation. The string of coiled tubing is plugged at the bottom. A third electrically conductive proppant is now placed through the new perforations and into the wellbore and surrounding formation along the upper end of the organic-rich rock formation.

FIGS. 2G(1) and 2G(2) show alternative approaches for completing the wellbore of FIG. 2A. In FIG. 2G(1), a second electrically conductive lead has been run into the wellbore all the way through the organic-rich rock formation. A nonconductive material is then placed in the wellbore along the second electrically conductive lead. A single lower packer is placed along the lower portion of the organic-rich rock formation and serves as a landing receptacle for the second electrically conductive lead.

In FIG. 2G(2), the second electrically conductive lead is again run into the wellbore through the organic-rich rock formation. However, an upper landing receptacle is also installed within the wellbore. An electrically insulative material is placed within the wellbore around the second electrically conductive lead to provide insulation.

FIG. 2H shows an alternate embodiment for completing a single wellbore using multiple proppants. Here, the single wellbore is completed using a sequence similar to that shown in FIGS. 2A through 2G(2), but wherein the wellbore is completed horizontally.

FIGS. 3A through 3I present a side, cross-sectional view of another wellbore. This wellbore demonstrates an alternative technique for heating an organic-rich rock formation using a single wellbore. In this instance, the wellbore is completed as a multi-lateral wellbore.

FIG. 3A provides a first cross-sectional view of the wellbore. Here, the wellbore has been lined with a string of casing. The wellbore is formed into the subsurface of the earth and also into an organic-rich rock formation. The wellbore includes a first deviated portion along the organic-rich rock formation.

FIG. 3B provides another cross-sectional view of the wellbore. Here, the casing has been perforated along a substantial portion of the deviated portion of the wellbore.

FIG. 3C shows a next view of the wellbore for heating the organic-rich rock formation. Here, a first electrically conductive proppant is injected into the wellbore and through the perforations in the casing. The first electrically conductive proppant is injected under a pressure greater than a formation-parting pressure in order to form a fracture. The fracture extends into the organic-rich rock along the deviated portion of the wellbore.

FIG. 3D presents a next step in the completion of the wellbore. Here, a second electrically conductive proppant is being injected into the wellbore and into the fracture. The second electrically conductive proppant displaces the first electrically conductive proppant from the bore of the wellbore and extends the fracture plane.

FIG. 3E presents yet another step in the completion of the wellbore. In this view, a whipstock has been set within a primary portion of the wellbore above the first deviated portion. A second deviated portion has been formed into the organic-rich rock formation above the first deviated portion. In this way, a multi-lateral wellbore is formed.

FIG. 3F presents still another step in the completion of the wellbore. The casing along the second deviated portion has been perforated. First electrically conductive proppant is being injected into the second deviated portion of the wellbore. The first electrically conductive proppant flows through the perforations, forming a second fracture within the organic-rich rock formation.

FIG. 3G presents a next step in the completion of the wellbore. Here, a third electrically conductive proppant is injected into the second deviated portion of the wellbore. The third electrically conductive proppant displaces the first electrically conductive proppant from the second deviated portion of the wellbore and into the new fracture. Of interest, the second fracture has linked with the first fracture.

FIG. 3H shows a next side view of the wellbore undergoing completion. The whipstock has been removed from the primary portion of the wellbore. In addition, a first electrically conductive lead has been run into the wellbore to a location proximate the heel of the first deviated portion of the wellbore.

FIG. 3I provides a final view of the wellbore. Here, a second electrically conductive lead has been run into the wellbore. The second electrically conductive lead extends to proximate the heel of the second deviated portion of the wellbore.

FIGS. 4A and 4B provide a single flow chart for a method of heating a subsurface formation using electrical resistance heating, in one embodiment. The flow chart provides steps for the heating. In this instance, a substantially vertical wellbore is provided for the heating.

FIGS. 5A and 5B provide a second flow chart for a method of heating a subsurface formation using electrical resistance heating, in an alternate embodiment. The flow chart shows the alternate steps for the heating. In this instance, a deviated wellbore is provided for the heating.

FIGS. 6A and 6B provide a single flow chart for yet another method for heating a subsurface formation using electrical resistance heating. This embodiment relates to the use of a multilateral wellbore.

DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS Definitions

As used herein, the term “hydrocarbon” refers to an organic compound that includes primarily, if not exclusively, the elements hydrogen and carbon. Hydrocarbons may also include other elements, such as, but not limited to, halogens, metallic elements, nitrogen, oxygen, and/or sulfur. Hydrocarbons generally fall into two classes: aliphatic, or straight chain hydrocarbons, and cyclic, or closed ring hydrocarbons, including cyclic terpenes. Examples of hydrocarbon-containing materials include any form of natural gas, oil, coal, and bitumen that can be used as a fuel or upgraded into a fuel.

As used herein, the term “hydrocarbon fluids” refers to a hydrocarbon or mixtures of hydrocarbons that are gases or liquids. For example, hydrocarbon fluids may include a hydrocarbon or mixtures of hydrocarbons that are gases or liquids at formation conditions, at processing conditions or at ambient conditions (15° C. and 1 atm pressure). Hydrocarbon fluids may include, for example, oil, natural gas, coalbed methane, shale oil, pyrolysis oil, pyrolysis gas, a pyrolysis product of coal, and other hydrocarbons that are in a gaseous or liquid state.

As used herein, the terms “produced fluids” and “production fluids” refer to liquids and/or gases removed from a subsurface formation, including, for example, an organic-rich rock formation. Produced fluids may include both hydrocarbon fluids and non-hydrocarbon fluids. Production fluids may include, but are not limited to, pyrolyzed shale oil, synthesis gas, a pyrolysis product of coal, carbon dioxide, hydrogen sulfide and water (including steam).

As used herein, the term “fluid” refers to gases, liquids, and combinations of gases and liquids, as well as to combinations of gases and solids, and combinations of liquids and solids.

As used herein, the term “gas” refers to a fluid that is in its vapor phase at 1 atm and 15° C.

As used herein, the term “condensable hydrocarbons” means those hydrocarbons that condense to a liquid at about 15° C. and one atmosphere absolute pressure. Condensable hydrocarbons may include a mixture of hydrocarbons having carbon numbers greater than 4.

As used herein, the term “non-condensable” means those chemical species that do not condense to a liquid at about 15° C. and one atmosphere absolute pressure. Non-condensable species may include non-condensable hydrocarbons and non-condensable non-hydrocarbon species such as, for example, carbon dioxide, hydrogen, carbon monoxide, hydrogen sulfide, and nitrogen. Non-condensable hydrocarbons may include hydrocarbons having carbon numbers less than 5.

As used herein, the term “heavy hydrocarbons” refers to hydrocarbon fluids that are highly viscous at ambient conditions (15° C. and 1 atm pressure). Heavy hydrocarbons may include highly viscous hydrocarbon fluids such as heavy oil, tar, and/or asphalt. Heavy hydrocarbons may include carbon and hydrogen, as well as smaller concentrations of sulfur, oxygen, and nitrogen. Additional elements may also be present in heavy hydrocarbons in trace amounts. Heavy hydrocarbons may be classified by API gravity. Heavy hydrocarbons generally have an API gravity below about 20 degrees. Heavy oil, for example, generally has an API gravity of about 10-20 degrees, whereas tar generally has an API gravity below about 10 degrees. The viscosity of heavy hydrocarbons is generally greater than about 100 centipoise at about 15° C.

As used herein, the term “solid hydrocarbons” refers to any hydrocarbon material that is found naturally in substantially solid form at formation conditions. Non-limiting examples include kerogen, coal, shungites, asphaltites, and natural mineral waxes.

As used herein, the term “formation hydrocarbons” refers to both heavy hydrocarbons and solid hydrocarbons that are contained in an organic-rich rock formation. Formation hydrocarbons may be, but are not limited to, kerogen, oil shale, coal, bitumen, tar, natural mineral waxes, and asphaltites. A formation that contains formation hydrocarbons may be referred to as an “organic-rich rock.”

As used herein, the term “tar” refers to a viscous hydrocarbon that generally has a viscosity greater than about 10,000 centipoise at 15° C. The specific gravity of tar generally is greater than 1.000. Tar may have an API gravity less than 10 degrees. “Tar sands” refers to a formation that has tar in it.

As used herein, the term “kerogen” refers to a solid, insoluble hydrocarbon that principally contains carbon, hydrogen, nitrogen, oxygen, and sulfur.

As used herein, the term “bitumen” refers to a non-crystalline solid or viscous hydrocarbon material that is substantially soluble in carbon disulfide.

As used herein, the term “oil” refers to a hydrocarbon fluid containing primarily a mixture of condensable hydrocarbons.

As used herein, the term “subsurface” refers to geologic strata occurring below the earth's surface. Similarly, the term “formation” refers to any definable subsurface region. The formation may contain one or more hydrocarbon-containing layers, one or more non-hydrocarbon containing layers, an overburden, and/or an underburden of any geologic formation. An “overburden” and/or an “underburden” is geological material above or below the formation of interest.

An overburden or underburden may include one or more different types of substantially impermeable materials. For example, overburden and/or underburden may include sandstone, shale, mudstone, or wet/tight carbonate (i.e., an impermeable carbonate without hydrocarbons). An overburden and/or an underburden may include a hydrocarbon-containing layer that is relatively impermeable. In some cases, the overburden and/or underburden may be permeable.

As used herein, the term “hydrocarbon-rich formation” refers to any formation that contains more than trace amounts of hydrocarbons. For example, a hydrocarbon-rich formation may include portions that contain hydrocarbons at a level of greater than 5 percent by volume. The hydrocarbons located in a hydrocarbon-rich formation may include, for example, oil, natural gas, heavy hydrocarbons, and solid hydrocarbons.

As used herein, the term “organic-rich rock” refers to any rock matrix holding solid hydrocarbons and/or heavy hydrocarbons. Rock matrices may include, but are not limited to, sedimentary rocks, shales, siltstones, sands, silicilytes, carbonates, and diatomites. Organic-rich rock may contain kerogen or bitumen.

As used herein, the term “organic-rich rock formation” refers to any formation containing organic-rich rock. Organic-rich rock formations include, for example, oil shale formations, coal formations, and tar sands formations.

As used herein, the term “pyrolysis” refers to the breaking of chemical bonds through the application of heat. For example, pyrolysis may include transforming a compound into one or more other substances by heat alone or by heat in combination with an oxidant. Pyrolysis may include modifying the nature of the compound by addition of hydrogen atoms which may be obtained from molecular hydrogen, water, carbon dioxide, or carbon monoxide. Heat may be transferred to a section of the formation to cause pyrolysis.

As used herein, the term “hydraulic fracture” refers to a fracture at least partially propagated into a formation, wherein the fracture is created through injection of pressurized fluids into the formation. While the term “hydraulic fracture” is used, the inventions herein are not limited to use in hydraulic fractures. The invention is suitable for use in any fracture created in any manner considered to be suitable by one skilled in the art. The fracture may be artificially held open by injection of a proppant material. Hydraulic fractures may be substantially horizontal in orientation, substantially vertical in orientation, or oriented along any other plane.

As used herein, the term “wellbore” refers to a hole in the subsurface made by drilling or insertion of a conduit into the subsurface. A wellbore may have a substantially circular cross section, or other cross-sectional shape (e.g., an oval, a square, a rectangle, a triangle, or other regular or irregular shapes). As used herein, the term “well”, when referring to an opening in the formation, may be used interchangeably with the term “wellbore.”

DESCRIPTION OF SELECTED SPECIFIC EMBODIMENTS

The inventions are described herein in connection with certain specific embodiments. However, to the extent that the following detailed description is specific to a particular embodiment or a particular use, such is intended to be illustrative only and is not to be construed as limiting the scope of the inventions.

FIG. 1 is a cross-sectional perspective view of an illustrative hydrocarbon development area 100. The hydrocarbon development area 100 has a surface 110. Preferably, the surface 110 is an earth surface on land. However, the surface 110 may be a seabed under a body of water, such as a lake or an ocean.

The hydrocarbon development area 100 also has a subsurface 120. The subsurface 120 includes various formations, including one or more near-surface formations 122, a hydrocarbon-bearing formation 124, and one or more non-hydrocarbon formations 126. The near surface formations 122 represent an overburden, while the non-hydrocarbon formations 126 represent an underburden. Both the one or more near-surface formations 122 and the non-hydrocarbon formations 126 will typically have various strata with different mineralogies therein.

The hydrocarbon development area 100 is for the purpose of producing hydrocarbon fluids from the hydrocarbon-bearing formation 124. The hydrocarbon-bearing formation 124 defines a rock matrix having hydrocarbons residing therein. The hydrocarbons may be solid hydrocarbons such as kerogen. Alternatively, the hydrocarbons may be viscous hydrocarbons such as heavy oil that do not readily flow at formation conditions. The hydrocarbon-bearing formation 124 may also contain, for example, tar sands that are too deep for economical open pit mining. Therefore, an enhanced oil recovery method involving heating is desirable.

It is understood that the representative formation 124 may be any organic-rich rock formation, including a rock matrix containing kerogen, for example. In addition, the rock matrix making up the formation 124 may be permeable, semi-permeable or non-permeable. The present inventions are particularly advantageous in shale oil development areas initially having very limited or effectively no fluid permeability. For example, initial permeability may be less than 10 millidarcies.

The hydrocarbon-bearing formation 124 may be selected for development based on various factors. One such factor is the thickness of organic-rich rock layers or sections within the formation 124. Greater pay zone thickness may indicate a greater potential volumetric production of hydrocarbon fluids. Each of the hydrocarbon-containing layers within the formation 124 may have a thickness that varies depending on, for example, conditions under which the organic-rich rock layer was formed. Therefore, an organic-rich rock formation such as hydrocarbon-bearing formation 124 will typically be selected for treatment if that formation includes at least one hydrocarbon-containing section having a thickness sufficient for economical production of hydrocarbon fluids.

An organic-rich rock formation such as formation 124 may also be chosen if the thickness of several layers that are closely spaced together is sufficient for economical production of produced fluids. For example, an in situ conversion process for formation hydrocarbons may include selecting and treating a layer within an organic-rich rock formation having a thickness of greater than about 5 meters, 10 meters, 50 meters, or even 100 meters. In this manner, heat losses (as a fraction of total injected heat) to layers formed above and below an organic-rich rock formation may be less than such heat losses from a thin layer of formation hydrocarbons. A process as described herein, however, may also include incidentally treating layers that may include layers substantially free of formation hydrocarbons or thin layers of formation hydrocarbons.

The richness of one or more sections in the hydrocarbon-bearing formation 124 may also be considered. For an oil shale formation, richness is generally a function of the kerogen content. The kerogen content of the oil shale formation may be ascertained from outcrop or core samples using a variety of data. Such data may include Total Organic Carbon content, hydrogen index, and modified Fischer Assay analyses. The Fischer Assay is a standard method which involves heating a sample of a hydrocarbon-containing-layer to approximately 500° C. in one hour, collecting fluids produced from the heated sample, and quantifying the amount of fluids produced.

An organic-rich rock formation such as formation 124 may be chosen for development based on the permeability or porosity of the formation matrix even if the thickness of the formation 124 is relatively thin. Subsurface permeability may also be assessed via rock samples, outcrops, or studies of ground water flow. An organic-rich rock formation may be rejected if there appears to be vertical continuity and connectivity with groundwater.

Other factors known to petroleum engineers may be taken into consideration when selecting a formation for development. Such factors include depth of the perceived pay zone, continuity of thickness, and other factors. For instance, the organic content or richness of rock within a formation will effect eventual volumetric production.

In order to access the hydrocarbon-bearing formation 124 and recover natural resources therefrom, a plurality of wellbores is formed. The wellbores are shown at 130, with some wellbores 130 being seen in cut-away and one being shown in phantom. The wellbores 130 extend from the surface 110 into the formation 124.

Each of the wellbores 130 in FIG. 1 has either an up arrow or a down arrow associated with it. The up arrows indicate that the associated wellbore 130 is a production well. Some of these up arrows are indicated with a “P.” The production wells “P” produce hydrocarbon fluids from the hydrocarbon-bearing formation 124 to the surface 110. Reciprocally, the down arrows indicate that the associated wellbore 130 is a heat injection well, or a heater well. Some of these down arrows are indicated with an “I.” The heat injection wells “I” inject heat into the hydrocarbon-bearing formation 124. Heat injection may be accomplished in a number of ways known in the art, including downhole or in situ electrically resistive heat sources, circulation of hot fluids through the wellbore or through the formation, and downhole burners.

In one aspect, the purpose for heating the organic-rich rock in the formation 124 is to pyrolyze at least a portion of solid formation hydrocarbons to create hydrocarbon fluids. The organic-rich rock in the formation 124 is heated to a temperature sufficient to pyrolyze at least a portion of the oil shale (or other solid hydrocarbons) in order to convert the kerogen (or other organic-rich rock) to hydrocarbon fluids. The resulting hydrocarbon liquids and gases may be refined into products which resemble common commercial petroleum products. Such liquid products include transportation fuels such as diesel, jet fuel and naphtha. Generated gases may include light alkanes, light alkenes, H₂, CO₂, CO, and NH₃.

The solid formation hydrocarbons may be pyrolyzed in situ by raising the organic-rich rock in the formation 124, (or heated zones within the formation), to a pyrolyzation temperature. In certain embodiments, the temperature of the formation 124 may be slowly raised through the pyrolysis temperature range. For example, an in situ conversion process may include heating at least a portion of the formation 124 to raise the average temperature of one or more sections above about 270° C. at a rate less than a selected amount (e.g., about 10° C., 5° C.; 3° C., 1° C., or 0.5° C.) per day. In a further embodiment, the portion may be heated such that an average temperature of one or more selected zones over a one month period is less than about 375° C. or, in some embodiments, less than about 400° C.

The hydrocarbon-rich formation 124 may be heated such that a temperature within the formation reaches (at least) an initial pyrolyzation temperature, that is, a temperature at the lower end of the temperature range where pyrolyzation begins to occur. The pyrolysis temperature range may vary depending on the types of formation hydrocarbons within the formation, the heating methodology, and the distribution of heating sources. For example, a pyrolysis temperature range may include temperatures between about 270° C. and 800° C. In one aspect, the bulk of a target zone of the formation 124 may be heated to between 300° C. and 600° C.

For in situ operations, the heating and conversion process occurs over a lengthy period of time. In one aspect, the heating period is from three months to four or more years.

Conversion of oil shale into hydrocarbon fluids will create permeability in rocks in the formation 124 that were originally substantially impermeable. For example, permeability may increase due to formation of thermal fractures within a heated portion caused by application of heat. As the temperature of the heated formation 124 increases, water may be removed due to vaporization. The vaporized water may escape and/or be removed from the formation 124 through the production wells “P.” In addition, permeability of the formation 124 may also increase as a result of production of hydrocarbon fluids generated from pyrolysis of at least some of the formation hydrocarbons on a macroscopic scale. For example, pyrolyzing at least a portion of an organic-rich rock formation may increase permeability within a selected zone to about 1 millidarcy, alternatively, greater than about 10 millidarcies, 50 millidarcies, 100 millidarcies, 1 Darcy, 10 Darcies, 20 Darcies, or even 50 Darcies.

It is understood that petroleum engineers will develop a strategy for the best depth and arrangement for the wellbores 130 depending upon anticipated reservoir characteristics, economic constraints, and work scheduling constraints. In addition, engineering staff will determine what wellbores “I” should be formed for initial formation heating.

In an alternative embodiment, the purpose for heating the rock in the formation 124 is to mobilize viscous hydrocarbons. The rock in the formation 124 is heated to a temperature sufficient to liquefy bitumen or other heavy hydrocarbons so that they flow to a production well “P.” The resulting hydrocarbon liquids and gases may be refined into products which resemble common commercial petroleum products. Such liquid products include transportation fuels such as diesel, jet fuel and naphtha. Generated gases may include light alkanes, light alkenes, H₂, CO₂, CO, and NH₃. For bitumen, the resulting hydrocarbon liquids may be used for road paving and surface sealing.

In the illustrative hydrocarbon development area 100, the wellbores 130 are arranged in rows. The production wells “P” are in rows, and the heat injection wells “I” are in adjacent rows. This is referred to in the industry as a “line drive” arrangement. However, other geometric arrangements may be used such as a 5-spot arrangement. The inventions disclosed herein are not limited to the arrangement of production wells “P” and heat injection wells “I” unless so stated in the claims.

In the arrangement of FIG. 1, each of the wellbores 130 is completed in the hydrocarbon-bearing formation 124. The completions may be either open-hole or cased-hole. The well completions for the production wells “P” may also include propped or unpropped hydraulic fractures emanating therefrom as a result of a hydraulic fracturing operation.

The various wellbores 130 are presented as having been completed substantially vertically. However, it is understood that some or all of the wellbores 130, particularly for the production wells “P,” could deviate into an obtuse or even horizontal orientation.

In the view of FIG. 1, only eight wellbores 130 are shown for the heat injection wells “I.” Likewise, only twelve wellbores 130 are shown for the production wells “P.” However, it is understood that in an oil shale development project or in a heavy oil production operation, numerous additional wellbores 130 will be drilled. In addition, separate wellbores (not shown) may optionally be formed for water injection, formation freezing, and sensing or data collection.

The production wells “P” and the heat injection wells “I” are also arranged at a pre-determined spacing. In some embodiments, a well spacing of 15 to 25 feet is provided for the various wellbores 130. The claims disclosed below are not limited to the spacing of the production wells “P” or the heat injection wells “I” unless otherwise stated. In general, the wellbores 130 may be from about 10 feet up to even about 300 feet in separation.

Typically, the wellbores 130 are completed at shallow depths. Completion depths may range from 200 to 5,000 feet at true vertical depth. In some embodiments, an oil shale formation targeted for in situ retorting is at a depth greater than 200 feet below the surface, or alternatively 400 feet below the surface. Alternatively, conversion and production occur at depths between 500 and 2,500 feet.

A production fluids processing facility 150 is also shown schematically in FIG. 1. The processing facility 150 is designed to receive fluids produced from the organic-rich rock of the formation 124 through one or more pipelines or flow lines 152. The fluid processing facility 150 may include equipment suitable for receiving and separating oil, gas, and water produced from the heated formation 124. The fluids processing facility 150 may further include equipment for separating out dissolved water-soluble minerals and/or migratory contaminant species, including, for example, dissolved organic contaminants, metal contaminants, or ionic contaminants in the produced water recovered from the organic-rich rock formation 124.

FIG. 1 shows three exit lines 154, 156, and 158. The exit lines 154, 156, 158 carry fluids from the fluids processing facility 150. Exit line 154 carries oil; exit line 156 carries gas; and exit line 158 carries separated water. The water may be treated and, optionally, re-injected into the hydrocarbon-bearing formation 124 as steam for further enhanced oil recovery. Alternatively, the water may be circulated through the hydrocarbon-bearing formation at the conclusion of the production process as part of a subsurface reclamation project.

In order to carry out the process described above in connection with FIG. 1, it is necessary to heat the subsurface formation 124. A preferred method offered herein is to employ heater wells “I” that generate electrically resistive heat.

As alluded to above, several designs have been previously offered for electrical heater wells. One example is found in U.S. Pat. No. 3,137,347 titled “In Situ Electrolinking of Oil Shale.” The '347 patent describes a method by which electric current is flowed through a fracture connecting two wells to get electric flow started in the bulk of the surrounding formation. Of interest, heating of the formation occurs primarily due to the bulk electrical resistance of the formation itself. F. S. Chute and F. E. Vermeulen, Present and Potential Applications of Electromagnetic Heating in the In Situ Recovery of Oil, AOSTRA J. Res., v. 4, p. 19-33 (1988) describes a heavy-oil pilot test where “electric preheat” was used to flow electric current between two wells to lower viscosity and create communication channels between wells for follow-up with a steam flood.

Another example is found in U.S. Pat. No. 7,331,385, mentioned briefly above. That patent is entitled “Methods of Treating a Subterranean Formation to Convert Organic Matter into Producible Hydrocarbons.” The '385 patent teaches the use of electrically conductive fractures to heat oil shale. According to the '385 patent, a heating element is constructed by forming wellbores in a formation, and then hydraulically fracturing the oil shale formation around the wellbores. The fractures are filled with an electrically conductive material which forms the heating element. Preferably, the fractures are created in a vertical orientation extending from horizontal wellbores. An electrical current is passed through the conductive fractures from about the heel to the toe of each well. To facilitate the current, an electrical circuit may be completed by an additional transverse horizontal well that intersects one or more of the vertical fractures. The process of U.S. Pat. No. 7,331,385 creates an “in situ toaster” that artificially matures oil shale through the application of electric heat. Thermal conduction heats the oil shale to conversion temperatures in excess of about 300° C., causing artificial maturation.

Yet another example of electrical heating is disclosed in U.S. Patent Publ. No. 2008/0271885 published on Nov. 6, 2008. This publication is entitled “Granular Electrical Connections for In Situ Formation Heating.” In this publication, a resistive heater is formed by placing an electrically conductive granular material within a passage formed along a subsurface formation and proximate a stratum to be heated. In this disclosure, two or three wellbores are completed within the subsurface formation. Each wellbore includes an electrically conductive member. The electrically conductive member in each wellbore may be, for example, a metal rod, a metal bar, a metal pipe, a wire, or an insulated cable. The electrically conductive members extend into the stratum to be heated.

Passages are also formed in the stratum creating fluid communication between the wellbores. In some embodiments, the passage is an inter-connecting fracture; in other embodiments, the passage is one or more inter-connecting bores drilled through the formation. Electrically conductive granular material is then injected, deposited, or otherwise placed within the passages to provide electrical communication between the electrically conductive members of the adjacent wellbores.

In operation, a current is passed between the electrically conductive members. Passing current through the electrically conductive members and the intermediate granular material causes resistive heat to be generated primarily from the electrically conductive members within the wellbores. FIGS. 30A through 33 of U.S. Patent Publ. No. 2008/0271885 are instructive in this regard.

U.S. Patent Publ. No. 2008/0230219 describes other embodiments wherein the passage between adjacent wellbores is a drilled passage. In this manner, the lower ends of adjacent wellbores are in fluid communication. A conductive granular material is then injected, poured or otherwise placed in the passage such that granular material resides in both the wellbores and the drilled passage. In operation, a current is again passed through the electrically conductive members and the intermediate granular material to generate resistive heat. However, in U.S. Patent Publ. No. 2008/0230219, the resistive heat is generated primarily from the granular material. FIGS. 34A and 34B are instructive in this regard.

U.S. Patent Publ. No. 2008/0230219 also describes individual heater wells having two electrically conductive members therein. The electrically conductive members are placed in electrical communication by conductive granular material placed within the wellbore at the depth of a formation to be heated. Heating occurs primarily from the electrically conductive granular material within the individual wellbores. These embodiments are shown in FIGS. 30A, 31A, 32, and 33.

In one embodiment, the electrically conductive granular material is interspersed with slugs of highly conductive granular material in regions where no or minimal heating is desired. Materials with greater conductivity may include metal filings or shot; materials with lower conductivity may include quartz sand, ceramic particles, clays, gravel, or cement.

Co-owned U.S. Pat. Publ. No. 2010/0101793 is also instructive. That application was published on Apr. 29, 2010 and is entitled “Electrically Conductive Methods for Heating a Subsurface Formation to Convert Organic Matter into Hydrocarbon Fluids.” The published application teaches the use of two or more materials placed within an organic-rich rock formation and having varying properties of electrical resistance. Specifically, the granular material placed proximate the wellbore is highly conductive, while the granular material injected into a surrounding fracture is more resistive. An electrical current is passed through the granular material in the formation to generate resistive heat. The materials placed in situ provide for resistive heat without creating hot spots near the wellbores.

Co-owned U.S. Pat. No. 7,331,385, U.S. Pat. Publ. No. 2010/0101793, and U.S. Patent Publ. No. 2008/0230219 each present efficient means for forming wellbores used for generating electrically resistive heat. However, each also preferably requires the use of two or more wellbores completed in close proximity with intersecting materials. Therefore, it is desirable to reduce the number of wells to be drilled while still taking advantage of the efficiencies offered through the use of conductive granular material.

FIGS. 2A through 2G present a side, cross-sectional view of a wellbore 200 undergoing completion in an organic-rich rock formation 250. The purpose for completing the wellbore 200 is to heat the organic-rich rock formation 250 and mobilize hydrocarbon fluids therein.

In one aspect, the organic-rich rock formation 250 comprises solid hydrocarbons. Examples of solid hydrocarbons include kerogen, shungites, and natural mineral waxes. In this instance, heating the organic-rich rock formation 250 pyrolyzes the solid hydrocarbons into hydrocarbon fluids. The hydrocarbon fluids may then be produced through production wells to the surface for further processing and commercial sale.

In another aspect, the organic-rich rock formation comprises heavy hydrocarbons such as heavy oil, tar, and/or asphalt. The heavy oil might make up a so-called “tar sands” formation. In this instance, heating the organic-rich rock formation 250 serves to mobilize the heavy oil or tar so that hydrocarbons may flow as a fluid through production wells (not shown) to the surface.

In either instance, the wellbore 200 extends from an earth surface 212 and into an earth subsurface 210. The wellbore 200 has an upper end 202 and a lower end 204. In the illustrative embodiment of the wellbore 200, the wellbore 200 is completed in a substantially vertical orientation. However, it is understood that this single-wellbore arrangement may alternatively be completed as a deviated or even substantially horizontal wellbore. In either instance, the wellbore 200 has a production portion that extends into the organic-rich rock formation 250.

FIG. 2A presents a first side, cross-sectional view of the wellbore 200. In this first view, the wellbore 200 has been formed. The wellbore 200 includes a bore 215 that extends into the earth subsurface 210 and the organic-rich rock formation 250. A string of casing 220 has been run into the bore 215. The string of casing 220 defines a bore 205 through which completion operations may be conducted. The casing 220 has an upper end 222 proximate the upper end 202 of the wellbore 200. In addition, the casing 220 has a lower end 224 proximate the bottom 204 of the wellbore.

At least an upper portion of the casing 220 is fixed in the bore 215 by means of a cement sheath 211. The cement sheath 211 resides within an annular region formed between the casing 220 and the surrounding earth bore 215. The cement sheath 211 protects the integrity of the bore 215 and also isolates surrounding earth formations.

Preferably, a portion of the casing 220 is fabricated from a non-conductive material. FIG. 2A shows two non-conductive sections 225 of the casing 220. The non-conductive sections 225 may be comprised of one or more joints of, for example, ceramic pipe. In the arrangement of FIG. 2A, one non-conductive section 225 is optionally placed at or near the top of the organic-rich rock formation 250, while another non-conductive section 225 is placed just above the lower end 224 of the casing 220. Additional non-conductive sections of pipe may be placed along the organic-rich rock formation 250 to ensure that current flows primarily through proppant placed in the formation 250, as shown below in connection with FIGS. 2G(1) and 2G(2).

In addition to the casing 220, a first electrically conductive lead 230 has been run into the bore 215. The electrically conductive lead 230 has an upper end 232 extending to the upper end 202 of the wellbore 200. In addition, the first electrically conductive lead 230 has a lower end 234 that extends into the organic-rich rock formation 250.

The first electrically conductive lead 230 is insulated with a tough rubber or other non-electrically conducting exterior. However, the very lowest portion of the bottom end 234 of the first electrically conductive lead 230 is exposed. An exposed portion is shown in FIG. 2A at 236. This exposed portion 236 preferably comprises thick copper wires, but may comprise other electrically conductive metal material.

The first electrically conductive lead 230 is preferably run into the bore 215 of the wellbore 200 with the casing 220. For example, the first electrically conductive lead 230 may be clipped or otherwise fastened to an outer diameter of the casing 220 during run-in with a depth control marker for future perforation. However, accommodations must be made to prevent the exposed lower end 236 of the first electrically conductive lead 230 from contacting the casing 220. This may be done, for example, by using suitable non-conductive spacers (not shown).

FIG. 2B provides a next cross-sectional view of the wellbore 200. This view demonstrates that the casing 220 has been perforated along the organic-rich rock formation 250. Perforations are seen at 226.

It can be seen in FIG. 2B that not all of the casing 220 has been perforated. In this respect, the casing 220 along an upper portion of the organic-rich rock formation 250 is left unperforated. This section of casing 220 will be perforated later, as demonstrated in connection with FIG. 2E. The non-conductive section 225 will not be perforated.

FIG. 2C presents a next cross-sectional view of the wellbore 200. In this view, a hydraulic fracturing operation has been conducted in the subsurface formation 250. Hydraulic fracturing is a process known in the art of wellbore completions wherein an injection fluid is pressurized within the wellbore above the fracture pressure of the formation. This develops one or more fracture planes within the surrounding rock to relieve the pressure generated within the wellbore. Hydraulic fractures are oftentimes used to create additional permeability along a production portion of a formation. In the present context, the hydraulic fracturing is used to provide a planar source for heating.

As part of the fracturing operation, a first electrically conductive proppant 253 has been injected into the bore 205 of the wellbore 200. The first electrically conductive proppant 253 is injected under high pressure through the perforations 226.

It can be seen in FIG. 2C that a fracture plane 255 has been created. The first electrically conductive proppant 253 fills the fracture plane 255. The first electrically conductive proppant 253 is carried into the wellbore, through the perforations 226, and into the fracture plane 255 via hydraulic fluid or other carrier medium.

It is important to note that the fracture plane 255 extends parallel to the wellbore 200. Because the wellbore 200 is vertical, this means the fracture plane 255 is formed at a depth where the fracture plane 255 is also oriented vertically. According to principles of geomechanics, fracture planes tend to form in a direction perpendicular to the direction of least minimum principal stress. For formations that are less than 1,000 feet, for example, fracture planes typically tend to form horizontally. For formations that are greater than about 1,000 feet in depth, fracture planes tend to form vertically. Thus, the vertical wellbore embodiment 200 shown in FIGS. 2A through 2C would preferably be used for the heating of organic-rich rock formations 250 that are deep, i.e., greater than about 305 meters (1,000 feet).

FIG. 2D presents a next side, cross-sectional view of the wellbore 200. Here, a string of coiled tubing 260 has been run into the casing 220. The coiled tubing 260 extends to proximate the lower end 204 of the wellbore 200. The coiled tubing 260 is fixed at the lower end 204 of the wellbore by means of a surrounding packer 265. The packer 265 provides annular isolation around the string of coiled tubing 260.

In the completion step shown in FIG. 2D, a second electrically conductive proppant 257 is being injected through the coiled tubing and into the lower portion 204 of the wellbore 200. The second electrically conductive proppant 257 displaces the first electrically conductive proppant 253 from the bore 205 of the wellbore 200. In addition, because the second electrically conductive proppant 257 is injected at a pressure greater than the fracture pressure of the organic-rich rock formation 250, the fracture plane 255 is preferably enlarged and extended. As a result of the injection of the second electrically conductive proppant 257, the second electrically conductive proppant is placed at both the lower end 204 of the wellbore 200, and partially into the fracture plane 255 at the lower end 204 of the wellbore 200.

In accordance with the methods herein, the first electrically conductive proppant 253 has a first bulk resistivity. Similarly, the second electrically conductive proppant has a second bulk resistivity. The second bulk resistivity is lower than the first bulk resistivity, meaning that the second electrically conductive proppant 257 is more electrically conductive than the first electrically conductive proppant 253.

Turning to FIG. 2E, FIG. 2E provides a next side, cross-sectional view of the wellbore 200. Here, new perforations 226 have been provided along the casing 220. These perforations 226 are located along an upper portion of the organic-rich rock formation 250. Moreover, the new perforations 226 are generally above the original fracture plane 255 and surround the exposed portion 236 of the first electrically conductive lead 230.

FIG. 2F shows yet another cross-sectional view of the wellbore 200. This represents a next step in the completion of the wellbore 200 for purposes of heating the organic-rich rock formation 250. In FIG. 2F, the string of coiled tubing 260 has once again been run into the bore 205 of the casing 220. However, the coiled tubing string 260 is only run into the bore 205 to a depth just below the new perforations 226. A packer 265 is again provided and set at a lower end of the coiled tubing string 260. The packer 265 provides annular isolation around the coiled tubing string 260. In addition, a lower end of the coiled tubing string 260 is plugged with plug 267.

In the step shown in FIG. 2F, a third electrically conductive proppant 259 is being injected into the wellbore 200. In order to accomplish the injection, the third electrically conductive proppant 259 is injected into the annulus between the coiled tubing string 260 and the surrounding casing 220. The third electrically conductive proppant 259 will fill the annulus along an upper portion of the organic-rich rock formation 250. In addition, the third electrically conductive proppant 259 should also at least partially invade the fracture plane 255 at the upper portion of the organic-rich rock formation 250.

As with the first 253 and second 257 electrically conductive proppants, the third electrically conductive proppant 259 will also have a bulk resistivity. The bulk resistivity of the third electrically conductive proppant 259 is also lower than the first bulk resistivity of the first electrically conductive proppant 253. This means that the third electrically conductive proppant 259 has a greater electrical conductivity than the first electrically conductive proppant 253.

The third electrically conductive proppant 259 may be comprised of the same material as that of the second electrically conductive proppant 257. Both the second 257 and third 259 electrically conductive proppants will be comprised of highly conductive materials such as metal filings, metal-coated particles, enriched petroleum coke, graphite, or combinations thereof. In contrast, the first electrically conductive proppant 253 will be comprised of material having a lower conductivity (and, reciprocally, a higher resistivity) such as metal particles mixed with ceramic chips, cement, silica, quarts, or mica.

FIGS. 2G(1) and 2G(2) provide a final step in the completion of the wellbore 200. FIGS. 2G(1) and 2G(2) provide alternate completion approaches. However, in both approaches it can be seen that the coiled tubing string 260 from FIG. 2F has been removed from the wellbore 200. Similarly, the packer 265 has been unset from the bore 205 and removed from the wellbore 200 with the coiled tubing string 260.

It can also be seen from each of FIGS. 2G(1) and 2G(2) that a second electrically conductive lead 270 has been run into the bore 205 of the wellbore 200. The second electrically conductive lead 270 has an upper end 272 proximate an earth surface 212, and a lower end 274 proximate a lower end of the organic-rich rock formation 250. Further, the lower end 274 of the second electrically conductive lead 270 is secured within the bore 205 by means of a lower landing packer 275L.

In each of FIGS. 2G(1) and 2G(2), an electrical junction box 280 is provided. The electrical junction box 280 receives an electricity supply through line 282. The electricity supply (not shown) may be part of a regional electrical grid. Alternatively, the electricity supply may be generated from a gas-fired turbine on location. In either instance, the electrical junction box 280 is part of an electrical circuit.

In order to form the electrical circuit, the first electrically conductive lead 230 is extended to the earth surface 212 and to the electrical junction box through surface line 230′. Similarly, the second electrically conductive lead 270 is extended from the earth surface 212 to the electrical junction box 280 by means of a separate electrical surface line 270′. In the illustrative arrangements of FIGS. 2G(1) and 2G(2), the first electrically conductive lead 230 and surface line 230′ represent a negative pole, while the second electrically conductive lead 270 and surface line 270′ represent a positive pole. However, it is understood that the polarities may be reversed.

In operation, electrical current is distributed through the electrical junction box 280, through electrical surface line 270′, through the second electrically conductive lead 270, to the bottom of the organic-rich rock formation 250, through the second electrically conductive proppant 257, into the fracture plane 255, through the first electrically conductive proppant 253, through the third electrically conductive proppant 259, to the exposed portion 236 of the first electrically conductive lead 230, through the electrical surface line 230′, and back to the electrical junction box 280. Of course, it is understood that the flow of electricity through this electrical circuit may be reversed by changing the polarity of the first 230 and second 270 electrically conductive leads. In either instance, considerable heat is generated within the organic-rich rock formation 250 through resistive heat generated by the flow of current through the first electrically conductive proppant 253.

As noted above, the bulk resistivity of the second electrically conductive proppant 257 and the third electrically conductive proppant 259 is lower than the bulk resistivity of the first electrically conductive proppant 257. This beneficially serves to prevent regions of excess heating, or “hot spots,” that might naturally occur in connection with the flow of electricity to and from the first 230 and second 270 electrically conductive leads.

In forming the electrical circuit, it is important to insulate the first electrically conductive lead 230 from the second electrically conductive lead 270. As noted above, the first electrically conductive lead 230 includes an insulative sheath along its length, except for an exposed portion 236 at the bottom 234 of the first electrically conductive lead 230. However, it is also important to prevent current from flowing to or from the first electrically conductive lead 230 and the second electrically conductive lead 270 along the production portion of the wellbore 200.

In order to provide the needed insulation and to prevent a “shorting” of the electrical circuit, the wellbore 200 is filled with an electrically insulative material 214. Examples of electrically insulative material include ceramic particles, clays, gravel, cement, and mica paste or particles. In each of the views of FIGS. 2G(1) and 2G(2), mica paste has been placed within the bore 205 of the wellbore 200 above the lower landing packer 275L. The insulative material 214 is further placed under pressure through the perforations 226 sufficient to provide electrical isolation along the casing 220 within the organic-rich rock formation 250. It is noted that the non-conductive section 225 will also help to prevent a short circuit between the electrical leads 230, 270.

By employing the electrically insulative material 214, the operator is able to ensure that electrical current will flow from one location along the wellbore 200 to another location within the wellbore through the first electrically conductive proppant 253. In this way, resistive heat is generated within the organic-rich rock formation 250 across the entire fracture plane 255.

In FIG. 2G(1), only the lower landing packer 275L is provided. FIG. 2G(2) provides an alternative completion, wherein an additional upper landing packer 275U is provided proximate the upper portion of the organic-rich rock formation 250. The upper landing packer 275U is placed below the location of the third electrically conductive proppant 259.

In the illustrative wellbore arrangement of FIGS. 2A through 2G, the wellbore 200 is completed in a substantially vertical orientation. However, it is again understood that the wellbore 200 may optionally be completed in a deviated or even substantially horizontal orientation. In this respect, the lower portion 204 of the wellbore and the portion of the casing 220 along the organic-rich rock formation 250 would be oriented in a substantially horizontal direction. For purposes of this disclosure, “substantially horizontal” means that an angle of at least 30 degrees off of vertical is created by the bore 215 of the wellbore towards at least a lower end 204.

FIG. 2H presents an alternate embodiment for completing a single wellbore 200H using multiple proppants. Here, the single wellbore 200H is completed using a sequence similar to that shown in FIGS. 2A through 2G(2). However, in FIG. 2H the wellbore 200H is completed horizontally.

The wellbore 200H is completed with one or more strings of casing 220. The casing 220 has a top end 222 at an upper end 202 of the wellbore 200H, and a bottom end 224 at a lower end 204 of the wellbore 200H. The casing 220 also includes at least one non-conductive section 225.

A fracture plane 255 is again formed within the subsurface formation 250. The illustrative fracture plane 250 is formed horizontally, although it may alternatively open up horizontally depending on the direction of least principal stress within the subsurface formation 250.

Completing a wellbore in a substantially horizontal orientation is beneficial for organic-rich rock formations that are deeper than, for example, 300 meters (1,000 feet). In this way, when the first electrically conductive proppant is injected into the formation as part of a hydraulic fracturing operation, a fracture plane is formed that extends along the deviated portion of the wellbore. Thus, before completing the wellbore, the operator should consider geomechanical forces and formation depth in determining what type of wellbore arrangement to employ. Preferably, a horizontal well is drilled perpendicular to the direction of minimum horizontal stress.

In the wellbore 200H, a first proppant 253 has been placed within the fracture plane 255. The first proppant 253 has been injected through perforations 226 as part of the fracturing process. In addition, a second proppant 257 has been placed along the lower end 224 of the casing 220. Finally, a third proppant 259 has been placed along a heel 206 of the casing 220. The proppants 253, 257, 259 are in accordance with the proppants described above.

The wellbore 200H also has a pair of electrical leads. In the arrangement of FIG. 2H, the casing 220 does not serve as one of the leads; instead, dedicated insulated wires 230H, 270H are run from the surface 212 and into the wellbore 200H. Lead 270H has an exposed tip terminating in the third proppant 259, while lead 230H has an exposed tip terminating in the second proppant 257. The leads 230H, 270H are preferably placed in the casing 220 before the respective proppants 259, 257 are pumped in.

As an alternative to using a monobore completion as shown in FIGS. 2A through 2G, whether vertical or horizontal, the operator may consider employing a multi-lateral wellbore. This means that a single vertical well is completed, with two substantially horizontal or deviated portions extending off of the primary vertical wellbore.

FIGS. 3A through 3I demonstrate steps for completing a multi-lateral wellbore. Each of these figures present a side, cross-sectional view of a wellbore 300 as may be used for heating an organic-rich rock formation 350.

First, FIG. 3A provides a cross-sectional view of a wellbore 300 having been formed into an earth subsurface 310. The wellbore 300 defines a bore 315 that has been formed through an earth subsurface 310. The wellbore 300 again has an upper portion 302 at the earth surface 312, and a lower portion 304′ within the organic-rich rock formation 350.

As with wellbore 200, wellbore 300 is completed with a string of casing 320. Preferably, the casing string 320 extends from the upper portion 302 to the lower portion 304′ of the wellbore 300. The casing 320 is held in place within the wellbore 300 by means of a cement sheath 311.

The wellbore 300 includes a first deviated portion 330. The illustrative deviated portion 330 is shown in a substantially horizontal orientation. However, it is understood that the first deviated portion 330 may be completed at an angle between 30 degrees and 90 degrees relative to vertical. The first deviated portion 330 defines a heel 332 and a toe 334. The casing 320 extends to the toe 334 along the first deviated portion 330.

FIG. 3B presents a next cross-sectional view of the wellbore 300. In this figure, the casing 320 has been perforated. Perforations 336 are seen along the casing 320 intermediate the heel 332 and the toe 334.

FIG. 3C presents a next step in the completion of the wellbore 300. Here, a first conductive proppant 355 has been injected into the bore 305 of the casing 330. The first electrically conductive proppant 355 is injected under pressure greater than the formation fracturing pressure using a hydraulic fracturing fluid. In this way, a fracture plane 335 is formed.

It can be seen from FIG. 3C that the first electrically conductive proppant 355 has filled the bore 305 of the wellbore. Further, the electrically conductive proppant 355 has filled the fracture plane 335. The electrically conductive proppant 355 is analogous to the first electrically conductive proppant 253 described in connection with FIG. 2E. In this respect, the first electrically conductive proppant 355 is designed to generate significant resistive heat when an electrical current is passed through the first fracture plane 355.

FIG. 3D shows a next cross-sectional view of the wellbore 300. Here, a second electrically conductive proppant 353 has been injected into the bore 305 of the casing 320. The second electrically conductive proppant 353 is specifically seen within the first deviated portion 330 of the wellbore 300. The second electrically conductive proppant 353 is injected under high pressure using a hydraulic fracturing fluid as a carrier medium.

The second electrically conductive proppant 353 displaces the first electrically conductive proppant 355 from the bore 305. This has the effect of at least partially extending or enlarging the first fracture plane 335. However, the second electrically conductive proppant 353 should not significantly invade the fracture plane 335 itself, but should remain primarily within the bore 305 along the first deviated portion 330.

It is also seen in FIG. 3D that a first landing tool 340′ has been set within the bore 305 of the casing 320. The landing tool 340′ is set within the bore 305 above the heel 332 of the deviated wellbore portion 335. A connector 345 is included within the landing tool 340′. As will be described later in connection with FIG. 3H, the connector 345 will receive a first electrically conductive lead.

FIG. 3E provides a next cross-sectional view of the wellbore 300. Here, a whipstock 360 has been landed in the bore 305 of the casing 320. The whipstock 360 includes a base plug 362. In addition, the whipstock 360 has an open concave face 365. Those of ordinary skill in the art will understand that the concave face 365 serves to direct a drill string and connected milling bit through a window to be formed in the casing 320.

It can be seen in FIG. 3E that a second deviated portion 370 has been formed in the wellbore 300. Thus, the wellbore 300 is now a multi-lateral wellbore. The second deviated portion 370 also has a heel 372 and a toe 374. It is noted that the second deviated portion 370 may be formed at any depth within the subsurface formation 350 so long as it is substantially parallel to the first deviated portion 330. In any instance, a non-conductive casing portion in the casing in the first deviated portion is not needed.

As noted above, the first deviated portion 330 forms a first lower portion 304′ of the wellbore 300. It is now noted that the second deviated portion 370 forms a second lower portion 304″ of the wellbore 300. Preferably, the second lower portion 304″ extends through the organic-rich rock formation 350 above the first lower portion 304′. Further, it is preferred that the second deviated portion 370 of the wellbore 300 extends above and perpendicular to the first deviated portion 330 within the same plane.

FIG. 3F presents yet a next view in the steps for completing the multilateral wellbore 300. Here, first electrically conductive proppant 355 has been injected through the bore 305 of the casing 300 and into the second deviated portion 370 of the wellbore 300. The plug 362 in the whipstock 360 prevents the first electrically conductive proppant 355 from traveling down to the first deviated portion 330.

It can be seen in FIG. 3F that the casing 320 along the second deviated portion 370 has been perforated. Perforations are shown at 376. The first electrically conductive proppant 355 is injected through the perforations 376 and into the surrounding organic-rich rock formation 350. A second fracturing plane 375 has now been formed.

The second fracturing plane 375 extends along the length of the second deviated portion 370 of the wellbore 300. The area of the second fracturing plane 375 is preferably about the same as the area of the first fracturing plane 335. Further, the first electrically conductive proppant 355 in the second fracturing plane 375 is composed of the same material as the first electrically conductive proppant 355 that fills the first fracture plane 355.

FIG. 3G presents a next cross-sectional view of the wellbore 300. Here, a third electrically conductive proppant 357 has been injected into the bore 305 of the casing 320. The third electrically conductive proppant 357 enters the second deviated portion 370 and displaces the first electrically conductive proppant 355. The third electrically conductive proppant 357 is injected under pressure as part of a hydraulic fracturing fluid. The pressure, which is greater than the formation fracturing pressure, serves to further enlarge the second fracturing plane 375. However, the third electrically conductive proppant 357 remains substantially within the bore 305 along the second deviated portion 370 and does not significantly invade the second fracturing plane 375.

The third electrically conductive proppant 357 has a third bulk resistivity. The third bulk resistivity is also lower than the first bulk resistivity, that is, the bulk resistivity of the first electrically conductive proppant 355.

It can be observed from FIG. 3G that the two fracture planes 335 and 375 have merged. The merger of two fracture planes is called coalescence. The concept of fracture coalescence has been discussed in SPE Paper No. 27, 718, published in 1994. See K. E. Olson and A. W. M. El-Rabaa, “Hydraulic Fracturing of the Multizone Wells in the Pegasus (Devonian) Field, West Texas,” SPE Paper No. 27,718 (Mar. 16-18, 1994).

After the third conductive proppant 357 has been placed along the second deviated portion 370 of the wellbore, the whipstock 360 is removed. In its place, a new landing tool may be provided proximate the heel 372 of the second deviated portion 370. FIG. 3H provides a next cross-sectional view of the wellbore 300. Here, it can be seen that the whipstock 360 from FIG. 3G has been removed from the bore 305 of the casing 320. Further, a second landing tool 340″ has been placed just below the heel 372 of the second deviated portion 370. The landing tool 340″ includes a connector 345. The connector 345 receives a first electrically conductive lead 338.

The electrically conductive lead 338 is an insulated wire having an exposed tip. The electrically conductive lead 338 extends from the earth surface 312, through the electrical connector 345 in each of the landing tools 340′, 340″ and then extends into at least the heel 332 of the first deviated portion 330 of the wellbore 300. Electrical communication is achieved between the first electrically conductive lead 338 and the first electrically conductive proppant 355 through the second electrically-conductive proppant 353.

It is noted that before inserting the third proppant 357, the operator may choose to insert a non-conductive material in the wellbore up to the location of the second deviated portion 370. The non-conductive material will pack in the first electrically conductive lead 338. The non-conductive material will also act as a whipstock to urge the third proppant 357 into the second deviated portion 370.

FIG. 3I provides a final cross-sectional view of the wellbore 300. In this view it can be seen that a second electrically conductive lead 378 has been placed within the bore 305 of the casing 320. The electrically conductive lead defines an insulated wire having an exposed lower portion 371. The second electrically conductive lead 378 extends from the upper portion 302 of the wellbore 300 into the heel 372 of the second deviated portion 370.

The exposed portion 371 of the second electrically conductive lead 378 is in electrical communication with the third electrically conductive proppant 357. This enables an electrical current to be carried through the lead 378 and into the second deviated portion 370 of the wellbore 300.

It can also be seen in FIG. 3I that an electrical circuit has been formed for carrying electrical current into the organic-rich rock formation 350. First, an electrical junction box 380 is provided at the earth surface 312. The junction box 380 receives electricity through an electrical line 382. Electrical line 382 may deliver electricity from a gas-powered turbine located on-site. Alternatively, electricity line 382 may be connected to a regional power grid. In any instance, the junction box 380 transmits electrical current to an electrical surface line 378′, which is then connected to the second electrically conductive lead 378. Similarly, an electrical surface line 338′ is connected at the earth surface 312 to the first electrically conductive lead 338.

It is preferred that a non-conductive section of casing 325 be provided above the first deviated portion 330 and below the whipstock 360. This helps ensure that electricity does not short circuit via the casing 320 since both lateral portions 330, 370 are drilled from the same parent wellbore 315. As an alternative, a portion of the casing 320 may be milled out below the location where the whipstock 360 will be placed.

In operation, electrical current is carried from the electrical junction box 380 to the electrical surface line 378′, down the bore 305 through the second electrically conductive lead 378, and to the third electrically conductive proppant 357. From there, current flows through the second fracture plane 375 and the first fracture plane 335. Due to the resistivity of the first granular proppant 355 within the fracture planes 375, 335, substantial heat is generated within the organic-rich rock formation 350. From there, the electrical current flows through the second electrically conductive proppant 353 in the first deviated portion 330 of the wellbore 300, through the first electrically conductive lead 338, into the electrical surface line 338′, and back to the electrical junction box 380.

In the above description of the flow of electrical current, it is understood that the direction of flow is dependent upon the polarity of the first 338 and second 378 electrically conductive leads. Those of ordinary skill in the art of power engineering will understand that the polarity of the leads 338, 378 and, accordingly, the direction of electrical current flow, may be reversed.

Based upon the illustrative wellbore arrangements 200, 300 described above, methods for heating a subsurface formation using electrical resistance heating are provided herein. Such methods are described in certain embodiments below in connection with FIGS. 4, 5, and 6. First, FIGS. 4A and 4B provide a single flowchart for a method 400 for heating a subsurface formation, in one embodiment. The method 400 is intended primarily for a wellbore that is completed in a substantially vertical orientation.

The method 400 first includes the step of providing a substantially vertical wellbore. This is shown in Box 405 of FIG. 4A. In accordance with the method 400, the wellbore penetrates an interval of organic-rich rock within a subsurface formation. The organic-rich rock may be, for example, a heavy oil such as bitumen. Alternatively, the organic-rich rock may comprise oil shale.

The method 400 also includes forming a fracture in the organic-rich rock. This step is indicated at Box 410. Where the wellbore is formed in a vertical orientation as indicated in the step of Box 405, the fracture in the organic-rich rock will be formed along a plane that is generally vertical in orientation. This, of course, assumes that geomechanical modeling and geological engineering studies have confirmed that a fracture plane will open up in a vertical manner upon the injection of hydraulic fracturing fluid at formation fracturing pressures.

The method 400 also includes placing a first electrically conductive proppant into the fracture. This is shown in Box 415. The first electrically conductive proppant has a first bulk resistivity. In operation, the operator will select a material as the electrically conductive proppant that has a limited conductivity. For example the first electrically conductive proppant may be fabricated from metal shavings that are mixed with ceramic or other substantially nonconductive particles that limit the flow of electrical current there through.

The method 400 will also include placing a second electrically conductive proppant at a first location within the wellbore. This is provided at Box 420 of FIG. 4A. The second electrically conductive proppant will also have a bulk resistivity. However, the bulk resistivity of the second electrically conductive proppant is a second bulk resistivity that is lower than the first bulk resistivity.

The operator will “tune” the second electrically conductive proppant to have a conductivity that is higher than the conductivity of the first electrically conductive proppant. Preferably, the second electrically conductive proppant is fabricated from metal shavings, steel shot, or calcined coke.

The method 400 will further include the step of placing a third electrically conductive proppant within the wellbore. This is indicated at Box 425. The third electrically conductive proppant is placed at a second location within the wellbore. Preferably, the second location is opposite the first location referenced in the step of Box 420, with the first electrically conductive proppant residing between the second and third electrically conductive proppants.

In one embodiment, the first location which contains the second electrically conductive proppant is located at the bottom end of the wellbore, while the second location which contains the third electrically conductive proppant is located proximate an upper boundary of the organic-rich rock formation.

The method 400 also includes providing an electrical source at the surface. This is shown at Box 430. The electrical source is designed to generate or otherwise provide an electrical current to the first electrically conductive proppant located within the fracture.

The method 400 also comprises providing a first electrical connection from the electrical source to the second electrically conductive proppant at the first location. This is seen at Box 435. Further, the method includes providing a second electrical connection from the electrical source to the third electrically conductive proppant at the second location. This is indicated at Box 440. The first and second electrical connections help provide an electrical circuit for delivering electricity through the first electrically conductive proppant within the fracture.

The first and second electrical connections are preferably insulated wires or cables. However, they may alternatively be insulated rods, bars, or metal tubes. The only requirement is that they transmit electrical current down to the interval to be heated, and that they are insulated from one another.

The method 400 also includes passing an electrical current through the fracture between the first and second locations. This is shown at Box 445 of FIG. 4B. Passing the electrical current generates heat by electrical resistivity primarily within the first electrically conductive proppant. Preferably, the resistivity of the first electrically conductive proppant is about 10 to 100 times greater than the resistivity of the second and third electrically conductive proppants. In one aspect, the resistivity of the first electrically conductive proppant is about 0.005 to 1.0 Ohm-Meters.

The method 400 may also optionally include producing hydrocarbon fluids from the subsurface formation to the surface. This is provided at Box 450. Production takes place through dedicated production wellbores, or “producers,” separate from the wellbore formed for heating.

The methods for heating a subsurface formation using electrical resistance heating disclosed herein may be employed where the wellbore includes a deviated portion. FIGS. 5A and 5B provide a flowchart showing an alternate method 500 for heating a subsurface formation. The method 500 again provides for using electrical resistance heating.

First, the method 500 includes providing a wellbore having a deviated portion. This is shown at Box 505 of FIG. 5A. The deviated portion represents a portion of the wellbore that is deviated by an angle of at least 30 degrees off of vertical. Preferably, the deviated portion is substantially horizontal.

The deviated portion of the wellbore penetrates along an interval of organic-rich rock within the subsurface formation. The organic-rich rock may comprise a heavy oil such as bitumen. In this case, heating the organic-rich rock mobilizes bitumen or other heavy oil so that it may flow to a production well for production. Alternatively, the organic-rich rock may comprise oil shale having kerogen. In this instance, heating the organic-rich rock pyrolyzes solid hydrocarbons into hydrocarbon fluids which then flow to the surface through separate production wells.

The method 500 also includes forming a fracture in the organic-rich rock. This is provided at Box 510. The fracture is formed along a plane that is generally parallel with the deviated portion of the wellbore.

It is noted that if the deviated portion is located within an organic-rich rock formation which is shallow, that is, less than about 305 meters (1,000 feet), then the fracture plane will most likely extend in a vertical orientation. However, if the organic-rich rock formation is located at a deeper depth, such as about 305 meters (1,000 feet) or greater, then the fracture plane will most likely be horizontal. Either orientation is functional for the method 500 of heating a subsurface formation as presented in FIGS. 5A and 5B.

The method 500 also includes placing a first electrically conductive proppant into the fracture. This is shown at Box 515. Placing the first electrically conductive proppant into the fracture will typically be performed by injecting a hydraulic fracturing fluid containing the first electrically conductive proppant during the step of Box 510 of forming a fracture. The first electrically conductive proppant will have a first bulk resistivity. The first electrically conductive proppant is “tuned” in order to have limited electrical conductivity. In this way, resistive heat is generated as electrical current is passed through the fracture.

The method 500 will next include placing a second electrically conductive proppant into the wellbore. This is seen at Box 520 of FIG. 5A. In the method 500, the second electrically conductive proppant is placed proximate to the toe of the deviated portion of the wellbore. However, the method 500 need not be limited to placing the second electrically conductive proppant at the toe.

The method 500 will further include placing a third electrically conductive proppant into the wellbore. This is indicated at Box 525. In this instance the third electrically conductive proppant is placed proximate the heel of the deviated portion of the wellbore. However, the method 500 need not be limited to placing the third proppant at the heel.

it is noted that both the second electrically conductive proppant and the third electrically conductive proppant will have a bulk resistivity. The second electrically conductive proppant will have a second bulk resistivity, while the third electrically conductive proppant will have a third bulk resistivity. Preferably, the second and third electrically conductive proppants are fabricated from the same material, such as metal shavings or steel shot, and will therefore have the same bulk resistivities. In any instance, the bulk resistivity of both the second and third electrically conductive proppants is lower than the first bulk resistivity from the first electrically conductive proppant.

The method 500 also includes providing an electrical source at the surface. This is seen at Box 530. As with the step of Box 430 in the method 400, the step of Box 530 in the method 500 employs an electrical source that may be, for example, from a regional power grid. Alternatively, electricity may be generated on-site through, for example, a gas powered turbine or a combined cycle power plant.

The method 500 also includes providing a first electrical connection from the electrical source to the second electrically conductive proppant. This is shown at Box 535. The method 500 further includes providing a second electrical connection from the electrical source to the third electrically conductive proppant. This is indicated at Box 540. Each of the first and second electrical connections comprises an electrically conductive lead such as an insulated copper or steel wire. Alternatively, an insulated metal bar, rod, or tubing may be employed. Again, the only requirement is that the electrical leads conduct electricity down to the organic-rich rock and that they be insulated from one another within the wellbore.

The method 500 also provides for passing electrical current through the fracture between the toe of the wellbore and the heel of the wellbore. This is shown at Box 545 of FIG. 5B. In this way, heat is generated by electrical resistivity within the first electrically conductive proppant. At the same time, because the second and third electrically conductive proppants have a relatively low resistivity, heat preferably is not significantly generated at the toe or heel of the wellbore.

Finally, the method 500 may optionally include producing hydrocarbon fluids from the subsurface formation to the surface. This is shown at Box 550 of FIG. 5B. Production is preferably provided through dedicated production wells, or “producers,” that are completed in or at the depths of the organic-rich rock formation. Hydrocarbon fluids are mobilized due to heating, and migrate to the production wells and to the surface.

Where multiple heater wells are employed, the heater wells may be placed in a pre-designated pattern. For example, heater wells may be placed in alternating rows with production wells. Alternatively, heater wells may surround one or more production wells. Flow and reservoir simulations may be employed to estimate temperatures and pathways for hydrocarbon fluids generated in situ as they migrate from their points of origin to production wells.

An array of heater wells is preferably arranged such that a distance between each heater well is less than about 21 meters (70 feet). A portion of an organic-rich rock formation may be heated with heater wells disposed substantially parallel to a boundary of hydrocarbon formation. In alternative embodiments, the array of heater wells may be disposed such that a distance between each heater well may be less than about 100 feet, or 50 feet, or 30 feet. Regardless of the arrangement or distance between the heater wells, in certain embodiments, a ratio of heater wells to production wells disposed within an organic-rich rock formation may be greater than about 5, 10, or more.

Yet a third method for heating a subsurface formation using electrically resistive heating is provided herein. This method employs a single wellbore that is completed as a multilateral wellbore.

FIGS. 6A and 6B provide a single flowchart for a method 600 for heating a subsurface formation using electrical resistance heating. The method 600 is designed for a wellbore having at least two deviated portions extending off of a primary or “parent” wellbore.

The method 600 first includes forming a wellbore having a first deviated portion. This is seen at Box 605 of FIG. 6A. The first deviated portion penetrates along an interval of organic-rich rock within a subsurface formation.

As with the methods 400 and 500, the method 600 may involve the mobilization of heavy hydrocarbons. In this instance, the organic-rich rock may comprise heavy hydrocarbons such as bitumen. Alternatively, the organic-rich rock may comprise shale oil. In this instance, heating the organic-rich rock will pyrolyze solid hydrocarbons into hydrocarbon fluids.

The method 600 also includes perforating the wellbore along the first deviated portion. This is seen at Box 610. Thereafter, the method 600 includes forming a fracture in the organic-rich rock from the first deviated portion. This is shown at Box 615. The fracture is formed along a plane that is generally parallel with the first deviated portion of the wellbore.

The method 600 also includes placing a first electrically conductive proppant into the fracture from the first deviated portion. This is provided at Box 620. Placing the first electrically conductive proppant into the fracture is performed by including the first electrically conductive proppant with hydraulic fracturing fluid used in forming the fracture from the first deviated portion. The first electrically conductive proppant will have a first bulk resistivity. The first electrically conductive proppant is “tuned” to have a resistivity such that significant heat is generated when an electrical current is passed through the first electrically conductive proppant.

The method further includes placing a second electrically conductive proppant within the first deviated portion of the wellbore. This is shown in Box 625 of FIG. 6A. Preferably, the second electrically conductive proppant is placed from a heel to a toe of the first deviated portion of the wellbore.

The second electrically conductive proppant will also have a bulk resistivity. In this instance the second electrically conductive proppant has a second bulk resistivity that is lower than the first bulk resistivity. In this way, electrical current may be passed through the second electrically conductive proppant en route to the first electrically conductive proppant without creating excessive heat.

The method 600 also includes forming a second deviated portion from the wellbore. The second deviated portion extends from a primary portion of the wellbore, and also penetrates along the interval of organic-rich rock. This is shown at Box 630.

It is preferred that the second deviated portion extend along a same vertical plane as the first deviated portion. It is also preferred that the first and second deviated portions have a similar length.

The method 600 also includes perforating the wellbore along the second deviated portion. This is shown at Box 635. Perforating the wellbore means perforating a string of casing placed along the second deviated portion as part of the well completion.

After perforating, the method 600 includes the step of forming another fracture in the organic-rich rock. In this instance the fracture is formed from the second deviated portion. This is shown at Box 640.

The fracture formed from the second deviated portion of the wellbore is also formed along a plane that is generally parallel with the second deviated portion of the wellbore. Further, the fracturing operation is carried out such that the second fracture links or coalesces with the fracture from the first deviated portion.

The method 600 further includes placing the first electrically conductive proppant into the fracture from the second deviated portion. This is shown in Box 645 of FIG. 6A. This means that additional material making up the first electrically conductive proppant is included with hydraulic fracturing fluid used for forming the fracture in the step of Box 640.

As noted, the fracture formed from the second deviated portion is linked or “coalesced” with the fracture formed from the first deviated portion. Pressure gauges at the surface should inform the operator when a linking of fractures has taken place. In this respect, the operator will observe a drop in pressure as fracturing fluid injected into the second deviated portion of the wellbore begins to communicate with the fracture formed from the first deviated portion of the wellbore. Linking the two fractures allows for the first electrically conductive proppant to become a single electrically conductive body.

The method 600 also includes placing a third electrically conductive proppant within the second deviated portion of the wellbore. This is shown at Box 650 of FIG. 6B. The third electrically conductive proppant has a third bulk resistivity. As with the second electrically conductive proppant, the bulk resistivity of the third electrically conductive proppant is lower than the bulk resistivity of the first electrically conductive proppant.

It is preferred that the second and third electrically conductive proppants be fabricated from the same material. Each electrically conductive proppant will have a relatively high degree of conductivity. This permits electrical current to flow from or to a deviated portion of the wellbore without creating undesirable hot spots along the deviated portions.

The method 600 also includes providing an electrical source at the surface. As with the electrical sources described in connection with methods 400 and 500, the electrical source used in the method 600 may be electricity obtained from a regional grid. Alternatively, electricity may be generated on-site through a gas turbine or a combined cycle power plant. The step of providing an electrical source is shown at Box 655.

The method 600 also includes providing a first electrical connection from the electrical source to the second electrically conductive proppant. This is shown at Box 660. The first electrical connection will extend from the surface to the first deviated portion of the wellbore.

The method 600 will further include providing a second electrical connection from the electrical source to the third electrically conductive proppant. This is provided at Box 665. The electrical connection extends from the surface to the second deviated portion in the wellbore.

The first electrical connection and the second electrical connection each comprises an electrically conductive lead. Preferably, each electrical connection comprises a copper or metal wire that is insulated. Alternatively, the electrical connections may be metal rods, bars or tubes. However, it is necessary that the first and second electrical connections be electrically insulated from one another along the primary wellbore, and that each electrical connection conducts electricity without generating significant resistive heat.

The first electrical connection and the second electrical connection help to form an electrical circuit within the wellbore and the organic-rich rock. The method 600 will then include passing electrical current through the fractures between the first and second deviated portions. This is shown at Box 670. Passing electrical current through the fractures will cause electrically resistive heat to be generated within the first electrically conductive proppant. This, in turn, will heat the surrounding organic-rich rock.

The method 600 finally will optionally include producing hydrocarbon fluids from the subsurface formation to the surface. This is shown at Box 675. Preferably, production will take place through separate dedicated production wells, or “producers.” As described in connection with the methods 400 and 500 above, hydrocarbon fluids will flow from the subsurface formation to the surface, where they will be further processed and then made available for further use or commercial sale.

As can be seen, various methods are provided herein for heating an organic-rich rock within a subsurface formation. The method may be employed with a plurality of heater wells, each of which represents a single wellbore that is completed in such a manner that electrically conductive proppant is placed within fractures from the wellbore. 

1. A method for heating a subsurface formation using electrical resistance heating, comprising: providing a wellbore having a production portion that penetrates an interval of organic-rich rock within the subsurface formation; forming a fracture in the organic-rich rock along a plane that is generally parallel with the production portion of the wellbore; placing a first electrically conductive proppant into the fracture, the first electrically conductive proppant having a first bulk resistivity; placing a second electrically conductive proppant at a first location within the wellbore, the second electrically conductive proppant having a second bulk resistivity that is lower than the first bulk resistivity; placing a third electrically conductive proppant at a second location within the wellbore spaced apart from the first location, the third electrically conductive proppant having a third bulk resistivity that also is lower than the first bulk resistivity; and passing electric current through the fracture between the first and second locations such that heat is generated by electrical resistivity primarily within the first electrically conductive proppant.
 2. The method of claim 1, wherein: the subsurface formation comprises bitumen; and the step of passing electric current heats the subsurface formation to at least partially mobilize the bitumen within the formation.
 3. The method of claim 1, wherein: the subsurface formation comprises oil shale; and the step of passing electric current heats the subsurface formation to pyrolyze at least a portion of the oil shale into hydrocarbon fluids.
 4. The method of claim 3, further comprising: providing an electrical source at a surface; providing a first electrical connection from the electrical source to the second electrically conductive proppant at the first location; and providing a separate second electrical connection from the electrical source to the third electrically conductive proppant at the second location; wherein the electrical source, the first electrical connection, the second electrically conductive proppant, the first electrically conductive proppant, the third electrically conductive proppant, and the second electrical connection form an electrical circuit.
 5. The method of claim 4, wherein the heat generated within the fracture from the first electrically conductive proppant is at least 25° C. greater than heat generated within the first and second locations from the second and third electrically conductive proppants.
 6. The method of claim 1, wherein: the production portion of the wellbore is completed vertically; and the fracture plane of the fracture is substantially vertical
 7. The method of claim 6, wherein (i) the first location is proximate a lower portion of the subsurface formation; (ii) the second location is proximate an upper boundary of the subsurface formation; or (iii) both.
 8. The method of claim 1, wherein: the production portion of the wellbore is a single bore completed substantially horizontally, thereby providing a heel and a single toe; and the fracture plane of the fracture is substantially horizontal or substantially vertical.
 9. The method of claim 8, wherein: the first location is proximate the toe; the second location is proximate the heel; and the first location and the second location each form a local region of relatively high electrical conductivity in comparison to the first electrically conductive proppant in the fracture of the horizontal production portion.
 10. The method of claim 1, wherein placing the first electrically conductive proppant into the fracture comprises. perforating the production portion of the wellbore; and injecting the first electrically conductive proppant through the perforations and into the fracture as part of forming the fracture.
 11. The method of claim 1, wherein: the wellbore comprises a primary portion; the production portion of the wellbore comprises at least two lateral wellbores having substantially horizontally production portions extending from the primary portion, thereby forming a multi-lateral wellbore; and each horizontal production portion has a heel adjacent the primary portion, and a toe distal from the primary portion.
 12. The method of claim 11, wherein placing the first electrically conductive proppant into the fracture comprises: perforating each of the horizontal production portions of the wellbore; forming a fracture comprises forming a fracture along each of the substantially horizontal production portions, and linking the fractures so that the fractures are in fluid communication; and injecting the first electrically conductive proppant through the perforations and into each of the formed fractures along the horizontal production portions as part of forming the fractures.
 13. The method of claim 12, wherein: placing a second electrically conductive proppant at a first location within the wellbore comprises placing the second electrically conductive proppant substantially along a length of a first of the substantially horizontally production portions; placing a third electrically conductive proppant at a second location within the wellbore comprises placing the third electrically conductive proppant substantially along a length of a second of the substantially horizontally production portions; and the second and third electrically conductive proppants are in electrical communication by means of the first granular proppant residing within the fractures.
 14. The method of claim 12, wherein: placing a second electrically conductive proppant at a first location within the wellbore comprises placing the second electrically conductive proppant proximate the heel of a first of the substantially horizontal production portions; and placing a third electrically conductive proppant at a second location within the wellbore comprises placing the third electrically conductive proppant proximate the toe of a second of the substantially horizontal production portions; and the second and third electrically conductive proppants are in electrical communication by means of the first granular proppant residing within the fractures.
 15. The method of claim 12, further comprising: placing a second electrically conductive proppant at a first location within the wellbore comprises placing the second electrically conductive proppant proximate the heel of each horizontal production portion of the wellbore; and placing a third electrically conductive proppant at a second location within the wellbore comprises placing the third electrically conductive proppant the toe of each horizontal production portion of the wellbore.
 16. The method of claim 1, wherein the second and third electrically conductive proppants each comprise metal shot, metal coated particles, calcined petroleum coke, graphite, or combinations thereof.
 17. The method of claim 16, wherein the second and third electrically conductive proppants are composed of substantially the same material.
 18. The method of claim 1, wherein placing the second and third electrically conductive proppants within the wellbore further comprises injecting each of the second and third electrically conductive proppants partially into the fracture.
 19. The method of claim 1, wherein the first electrically conductive proppant comprises metal shot, metal coated particles, coke, graphite, or combinations thereof.
 20. The method of claim 19, wherein the first electrically conductive proppant further comprises silica, ceramic, cement, or combinations thereof.
 21. The method of claim 19, wherein the resistivity of the first electrically conductive proppant is about 10 to 100 times greater than the resistivity of the second and third electrically conductive proppants.
 22. The method of claim 1, wherein the bulk resistivity of the first electrically conductive proppant is about 0.005 to 1.0 Ohm-Meters.
 23. The method of claim 1, further comprising: placing a substantially non-conductive material within the production portion of the wellbore between the second and third electrically conductive proppants.
 24. The method of claim 1, further comprising: producing hydrocarbon fluids from the subsurface formation to a surface.
 25. A method for heating a subsurface formation using electrical resistance heating, comprising: providing a wellbore having a production portion that penetrates an interval of oil shale within the subsurface formation; forming a fracture in the oil shale interval along a plane that is generally parallel with the production portion of the wellbore; injecting a first electrically conductive proppant into the fracture, the first electrically conductive proppant having a first bulk resistivity; placing a second electrically conductive proppant at first and second spaced-apart locations within the wellbore, the second electrically conductive proppant having a second bulk resistivity that is lower than the first bulk resistivity; placing a substantially non-conductive material within the wellbore intermediate the first and second locations; installing a first electrically conductive lead in the wellbore providing electrical communication between an electricity source at the surface and the second electrically conductive proppant at the first location; installing a second electrically conductive lead in the wellbore providing electrical communication between the electricity source at the surface and the second electrically conductive proppant at the second location; and passing electric current through the fracture such that: an electrical circuit is formed between the electricity source at the surface, the first electrically conductive lead, the second electrically conductive proppant at the first location; the first electrically conductive proppant in the fracture, the second electrically conductive proppant at the second location, and the second electrically conductive lead; heat is generated by electrical resistivity within the first electrically conductive proppant sufficient to pyrolyze at least a portion of the oil shale into hydrocarbon fluids; and the heat generated within the fracture is greater than heat generated within the first and second locations.
 26. The method of claim 25, wherein: the production portion of the wellbore is completed substantially vertically; and the fracture plane of the fracture is substantially vertical.
 27. The method of claim 25, wherein: the production portion of the wellbore is completed as a single substantially horizontally bore, thereby forming a heel and a single toe; and the fracture plane of the fracture is either substantially horizontal or substantially vertical.
 28. The method of claim 27, wherein: the first location is proximate the toe; the second location is proximate the heel; and the first location and the second location each form a local region of relatively high electrical conductivity in comparison to the first electrically conductive proppant in the fracture of the horizontal production portion.
 29. The method of claim 25, wherein: the wellbore comprises a substantially vertical parent portion; the production portion of the wellbore comprises at least two lateral bores having substantially horizontal portions; each lateral wellbore has a heel adjacent a parent wellbore, and a toe distal from the parent wellbore extending from the parent portion, thereby forming a multi-lateral wellbore; and forming a fracture comprises forming a fracture along each of the substantially horizontal production portions.
 30. The method of claim 29, wherein: placing a second electrically conductive proppant at a first location within the wellbore comprises placing second electrically conductive proppant substantially along a length of a first of the substantially horizontally production portions; and placing a second electrically conductive proppant at a second location within the wellbore comprises placing second electrically conductive proppant substantially along a length of a second of the substantially horizontally production portions.
 31. The method of claim 25, wherein the resistivity of the first electrically conductive proppant is about 10 to 100 times greater than the resistivity of the second electrically conductive proppant.
 32. The method of claim 25, wherein the second electrically conductive proppant comprises metal shot, metal coated particles, coke, graphite, or combinations thereof.
 33. A system for electrically heating an organic-rich rock formation below an earth surface, the system comprising: an electricity source at the earth surface; a wellbore having a production portion that penetrates an interval of solid organic-rich rock within the subsurface formation; a fracture in the organic-rich rock along a plane that is generally parallel with the production portion of the wellbore; a first electrically conductive proppant within the fracture, the first electrically conductive proppant having a first bulk resistivity; a second electrically conductive proppant at a first location within the wellbore, the second electrically conductive proppant having a second bulk resistivity that is lower than the first bulk resistivity and being in electrical communication with the first electrically conductive proppant; a third electrically conductive proppant at a second location within the wellbore spaced apart from the first location, the third electrically conductive proppant having a third bulk resistivity that also is lower than the first bulk resistivity, and the third electrically conductive proppant being in electrical communication with the first electrically conductive proppant; a first electrical lead in the wellbore providing electrical communication between the electricity source at the surface and the second electrically conductive proppant at the first location; and a second electrical lead in the wellbore providing electrical communication between the electricity source and the second electrically conductive proppant at the second location; wherein: the second electrical lead is electrically insulated from the first electrical lead within the wellbore; and the electricity source, the first electrical lead, the second electrically conductive proppant, the first electrically conductive proppant, the third electrically conductive proppant, and the second electrical lead form an electrical circuit.
 34. The system of claim 33, wherein the organic-rich rock formation comprises oil shale.
 35. The method of claim 33, wherein the second and third electrically conductive proppants are composed of the same material.
 36. The system of claim 33, further comprising: a substantially non-conductive material within the wellbore between the second and third electrically conductive proppants.
 37. The system of claim 36, wherein the substantially non-conductive material comprises mica, silica, quartz, cement chips, or combinations thereof.
 38. The system of claim 33, wherein the bulk resistivity of the first electrically conductive proppant is less than about 0.005 to 1.0 Ohm-meters.
 39. The system of claim 33, wherein the bulk resistivities of the second and third electrically conductive proppants is at least 10 times less than that of the first electrically conductive proppant.
 40. The system of claim 33, wherein the wellbore comprises one or more strings of casing, with at least a portion of the casing being non-conductive. 